Hydrate-inhibiting well fluids

ABSTRACT

A method of treating a well including injecting a well-treating fluid into the well, where the well-treating fluid comprises a glycol compound and an organic liquid, the glycol compound and organic liquid being present in amounts selected to achieve a desired density. In another embodiment, a well fluid including a glycol compound an organic liquid, and a salt, wherein the glycol compound, organic liquid, and salt are present in amounts selected to achieve a predetermined density is disclosed.

CROSS-REFERENCE TO RELATED APPLICATIONS

[0001] This application claims priority pursuant to 35 U.S.C. §119 of U.S. Provisional Patent Application No. 60/374,049 filed on Apr. 19, 2002, entitled “Well Fluid,” in the name of William E. Foxenberg. This provisional application is incorporated herein by reference. This application also claims priority pursuant to 35 U.S.C. §119 of U.S. Provisional Patent Application No. 60/412,543 filed on Sep. 20, 2002, entitled “Hydrate-Inhibiting Well Fluids,” in the names of William E. Foxenberg, Michael T. Darring, Kim J. Gobert, David P. Kippie, and Robert L. Horton. This provisional application is incorporated herein by reference.

BACKGROUND OF INVENTION

[0002] 1. Field of the Invention

[0003] The invention relates generally to wellbore fluids. More particularly, the present invention relates to non-aqueous, non-corrosive packer fluids.

[0004] 2. Background Art

[0005] When drilling or completing wells in earth formations, various fluids typically are used in the well for a variety of reasons. For the purposes herein, such fluid will be referred to as “well fluid.” In particular, one type of commonly used well fluid is known as a “packer fluid.” The term packer fluid means a fluid that is left in the annular region of a well between tubing and outer casing above a packer. The main functions of a packer fluid are: (1) to provide hydrostatic pressure in order to lower differential pressure across a sealing element, (2) to lower differential pressure on a wellbore and casing to prevent collapse and (3) to protect metals and elastomers from corrosion or deterioration. Generally, they should be of sufficient density to control the producing formation, be solids-free and resistant to viscosity changes over long periods of time, and be noncorrosive to the wellbore and completion components.

[0006] When setting a packer, it is desirable to place a fluid in the annulus that is solids-free, thermally stable and maintains a selected hydrostatic pressure. In some situations, a modified drilling mud is used as the packer fluid. However, the lack of long-term chemical stability and of long-term solids suspension are properties that limit the use of drilling mud. In many situations, a solids-free brine is used as the packer fluid in order to maintain long-term chemical stability and obviate the need for long-term solids suspension. These fluids, in some cases, are prone to form hydrates with high pressure hydrocarbon gas in the formation. In other cases, the fluid must meet certain performance specifications such as density, hydrate inhibition, viscosity and annulus compatibility that cannot otherwise be met by standard packer fluids, i.e., salt solutions and/or drilling muds of well-established composition.

SUMMARY OF INVENTION

[0007] In one aspect, the present invention relates to a method of treating a well including injecting a substantially water-free well-treating fluid into the well, where the well-treating fluid comprises a glycol compound and an organic liquid, the glycol compound and the organic liquid being present in amounts selected to achieve a predetermined density.

[0008] In another aspect, the present invention relates to a substantially water-free well fluid including a glycol compound and an organic liquid, where the glycol compound and the organic liquid are present in amounts selected to achieve a predetermined density.

[0009] In one aspect, the present invention relates to a method of treating a well including injecting a well-treating fluid into the well, where the well-treating fluid comprises water, a glycol compound, and other organic liquids in which the combination of fluids meets pre-set performance characteristics such as density, viscosity, hydrate inhibition, and compatibility with other fluids and elements in the annulus.

[0010] In one aspect, the present invention relates to a well fluid that includes water, a glycol compound, and other organic liquids in which the combination of fluids meets pre-set performance characteristics such as density, viscosity, hydrate inhibition, and compatibility with other fluids and elements in the annulus.

[0011] In another aspect, the present invention relates to a well fluid that includes a glycol compound, and a quaternary amine salt, where the glycol compound and the quaternary amine salt are present in amounts selected to achieve a predetermined density.

[0012] Other aspects and advantages of the invention will be apparent from the following description and the appended claims.

DETAILED DESCRIPTION

[0013] When setting a packer, it is desirable to have a fluid in the well annulus that is solids-free, thermally stable, and maintains a selected hydrostatic pressure. This invention relates to aqueous or non-aqueous fluids that can achieve a relatively broad range of densities without requiring solids, and are true solutions rather than emulsions or suspensions.

[0014] Glycols, such as ethylene glycol, propylene glycol, and others can be mixed at a very broad range of ratios with water and/or organic liquids such as alcohols, glycol ethers and others to form fluid mixtures having densities ranging from low (˜7 lbm/gal) to high (˜11 lbm/gal), depending on desired properties. Lbm/gal is a unit of density, which one of ordinary skill in the art would interpret as pound per gallon, or more specifically pound mass per gallon. Such mixtures inhibit hydrates because the mixture is either substantially free of water or the water is made inhibitive by virtue of the glycol and alcohol. Of course, some water is absorbed from the atmosphere and, therefore, some water is present in the glycol, but this amount is insufficient to make the fluid corrosive. These mixtures can also be viscosified with certain polymers, known within the oil and gas industry, to achieve highly viscous fluids that show excellent thermal insulation by virtue of their heat capacities, thermal conductivities and viscosities.

[0015] In one embodiment, the present invention describes the development of non-aqueous, non-solids laden, non-corrosive, hydrate inhibitive well fluids (or packer fluids) for use in oil field production annuli. The well fluids are prepared to desired densities for annular pressure control by proportioning miscible, non-aqueous fluids together. The non-aqueous fluids include glycols, glycol-ethers, alcohols and other organic liquids. The well fluids may contain soluble salts to achieve specific densities. The well fluids may be viscosified with synthetic or biopolymers to reduce convective currents, needed in some cases for annular heat insulation.

[0016] In another embodiment, the present invention describes the development of non-solids laden, non-corrosive, hydrate inhibitive well fluids for use in oil field production annuli. The fluid is prepared to desired densities for annular pressure control by proportioning miscible fluids together with water. These fluids include glycols, glycol-ethers, alcohols and other organic liquids. The fluids may contain soluble salts to achieve specific densities. The fluids may be viscosified with synthetic or biopolymers to reduce convective currents, needed in some cases for annular heat insulation.

[0017] One of ordinary skill in the art would appreciate that a glycol compound and an organic liquid may be mixed in amounts sufficient to yield a desired density. In addition, multiple glycol compounds and multiple organic liquids may be mixed, with or without water, so long as the mixture remains a solution.

EXAMPLE 1

[0018] In one embodiment, a well fluid in accordance with one embodiment of the present invention comprises a mixture of 0.2 barrels of methanol, 0.35 barrels of monoethylene glycol (MEG), 0.42 barrels of water, and a sufficient amount of a CaBr₂ solution, having a density of 14.5 ppg, to form a well fluid, referred to as formulation 1 herein, having an overall density of approximately 8.6 ppg.

EXAMPLE 2

[0019] In another embodiment, a well fluid in accordance with one embodiment of the present invention comprises a mixture 0.2 barrels of methanol, 0.35 barrels of monoethylene glycol (MEG), 0.42 barrels of water, and a sufficient amount of a CaBr₂ solution, having a density of 15.3 ppg, to form a well fluid, referred to as formulation 2 herein, having an overall density of approximately 8.8 ppg. While particular salts, and particular densities are referenced in the above embodiments, it should be understood that the salt types and concentrations may also vary from zero to saturation, according to density/compatibility requirements.

[0020] At temperatures of at least 30° F., aqueous fluids are susceptible to gas hydrate formation if high-pressure gas is encountered. Typical oilfield pressures exceed 8,000 psi. An additional consideration is that well fluids having a density of 8.6 ppg (achievable with 3.5-4.5 wt % salt) are often used. This salt concentration is not adequate to prevent hydrate formation under the combination of low salinity fluid, low temperature and high gas pressure, should such a combination occur in the wellbore. Therefore, other means of hydrate prevention, while maintaining density control, are desired.

[0021] The present invention has discovered that advantageously, mixtures of glycol and organic liquids are effective hydrate inhibitors.

[0022] In testing formulations 1 and 2, it was discovered that the well fluids provided hydrate suppression at pressures greater than 8,000 psi at 38° F. Second, the well fluids maintained a density of about 8.5-8.8 ppg at wellbore conditions. Third, a viscosity of less than 30 centiPoise (cP) at mudline temperature (38-40° F.) and less than 30 cP at 8,200 psi was maintained. Fourth, the tested formulations provided long-term stability (>24 hours) at wellbore temperature (38-280° F.) and pressure (8,200 psi). In addition, well fluids of the present invention were found to be compatible with a large number of wellbore elastomers/wellbore fluids.

[0023] In the above formulations, it was discovered that the presence of CaBr₂ salt could cause precipitates to form. Therefore, additional well fluids were formulated, whereby the CaBr₂ solution was replaced by volume ratios of methanol, monoethylene glycol and water to a specified density.

[0024] Further formulations are shown in Table 1 below. TABLE 1 Hydrate Formation Parameters for Water - Methanol - MEG - Salt Mixtures wt % Hydrate Hydrate Density wt % Wt % wt % KCI Temp @ psi of Water Methanol MEG (10.8 ppg) 9,000 psi 37° F. Mixture⁽¹⁾ 100 87° F. 188 psi ˜8.33 ppg 97 3 87° F. 188 psi ˜8.4 ppg 52 45 3 44° F. 6,600 psi ˜7.7 ppg 47 50 3 36° F. 11,000 psi ˜7.6 ppg 52 45 3 39° F. 8,670 psi ˜8.8 ppg 47 50 3 30° F. 11,000 psi ˜8.9 ppg 52 25 20 3 50° F. 3.600 psi ˜8.2 ppg 47 30 20 3 42° F. 6,660 psi ˜8.2 ppg 47 20 30 3 44° F. 6,660 psi ˜8.4 ppg 42 20 35 3 36° F. 11,000 psi ˜8.5 ppg

[0025] In yet other embodiments of the present invention, formulations are produced involving (1) halide brines, formate brines, and acetate brines, such as, for example, those based on tetramethylammonium chloride, tetramethylammonium bromide, tetramethylammonium formate, tetramethylammonium acetate, tetraethylammonium chloride, tetraethylammonium bromide, tetraethylammonium formate, tetraethylammonium acetate, tetrapropylammonium chloride, tetrapropylammonium bromide, tetrapropylammonium formate, tetrapropylammonium acetate, tetrabutylammonium chloride, tetrabutylammonium bromide, tetrabutylammonium formate, tetrabutylammonium acetate, ZnCl₂, ZnBr₂, CaBr₂, ZnBr₂/CaBr₂ blends, ZnBr₂/CaBr₂/CaCl₂ blends, CsBr, CsI, CsHCO₂, and mixtures thereof, (2) ethylene glycol solutions of tetramethylammonium chloride, tetramethylammonium bromide, tetramethylammonium formate, tetramethylammonium acetate, tetraethylammonium chloride, tetraethylammonium bromide, tetraethylammonium formate, tetraethylammonium acetate, tetrapropylammonium chloride, tetrapropylammonium bromide, tetrapropylammonium formate, tetrapropylammonium acetate, tetrabutylammonium chloride, tetrabutylammonium bromide, tetrabutylammonium formate, tetrabutylammonium acetate, ZnCl₂, ZnBr₂, CaBr₂, ZnBr₂/CaBr₂ blends, ZnBr₂/CaBr₂/CaCl₂ blends, CsBr, CsI, CsHCO₂, and mixtures thereof, and (3) methanol solutions of tetramethylammonium chloride, tetramethylammonium bromide, tetramethylammonium formate, tetramethylammonium acetate, tetraethylammonium chloride, tetraethylammonium bromide, tetraethylammonium formate, tetraethylammonium acetate, tetrapropylammonium chloride, tetrapropylammonium bromide, tetrapropylammonium formate, tetrapropylammonium acetate, tetrabutylammonium chloride, tetrabutylammonium bromide, tetrabutylammonium formate, tetrabutylammonium acetate, ZnCl₂, ZnBr₂, CaBr₂, ZnBr₂/CaBr₂ blends, ZnBr₂/CaBr₂/CaCl₂ blends, CsBr, CsI, CsHCO₂, and mixtures thereof. Furthermore, (4) blends of the above mentioned brines and methanol solutions, (5) blends of the above mentioned brines and ethylene glycol solutions, (6) blends of the above mentioned ethylene glycol solutions, and methanol solutions, and (7) blends of the above mentioned brines, ethylene glycol solutions, and methanol solutions are also within the scope of the present invention.

[0026] Accordingly, in another aspect, the present invention relates to well fluids comprising a glycol compound and a quaternary amine salt. Furthermore, the glycol compound and quaternary amine may be mixed with an organic liquid, as described above, or with numerous other compounds. In addition, mixtures of any or all of the above compounds may be used in connection with the present invention. The above list is not intended to be a comprehensive list of all suitable mixtures within the scope of the present invention. One of ordinary skill in the art, having reference to this specification, will recognize that other mixtures are within the scope of the present invention.

EXAMPLE 3

[0027] As a third example of the formulations in accordance with one embodiment of the present invention, a solution comprising 200 grams of ethylene glycol and 150 grams of tetrabutylammonium bromide was prepared. The solution had a density of 9.0 ppg and a TCT (Thermodynamic Crystallization Temperature) <25° F. This fluid is highly inhibitive of hydrates. In this third example, the addition of salt to ethylene glycol caused the density to drop from about 9.3 ppg to 9.0, a highly unusual and surprising result having considerable utility. Typically, salts like CaBr₂, NaCl, and the like, cause the density of ethylene glycol to increase upon the addition of the salt to the ethylene glycol. In contrast, when the salt is, for example, tetrabutylammonium bromide, the density decreases. Other salts that exhibit this surprising behavior include tetramethylammonium chloride, tetramethylammonium acetate, and the like.

EXAMPLE 4

[0028] As a fourth example of these formulations, a solution comprising 200 grams of ethylene glycol and 400 grams of tetrabutylammonium bromide was prepared. The solution had a density of 9.0 ppg, substantially the same as that of the third example, another highly surprising result—that a substantial amount of a salt with density substantially greater than 9.0 ppg could be added to a solution without any appreciable density increase in the solution. This fluid is highly inhibitive of hydrates.

EXAMPLE 5

[0029] As a fifth example of these formulations, a solution comprising 180 grams of ethylene glycol, 135 grams of tetrabutylammonium bromide and 35 grams of methanol was prepared. The solution had a density <9.0 ppg. This fluid is highly inhibitive of hydrates.

EXAMPLE 6

[0030] As a sixth example of these formulations, a solution comprising 180 grams of ethylene glycol, 360 grams of tetrabutylammonium bromide and 60 grams of methanol was prepared. The solution had a density <9.0 ppg. This fluid is highly inhibitive of hydrates.

EXAMPLE 7

[0031] As a seventh example of these formulations, a solution comprising 50 grams of ethylene glycol and 75 grams of tetramethylammonium acetate. The solution had a density 8.7 ppg. This example further illustrates the suprisingly the lower of these solutions. This fluid is highly inhibitive of hydrates.

COMPARATIVE EXAMPLE

[0032] As a comparison, a solution comprising 200 grams of water and 200 grams of tetrabutylammonium bromide was prepared; however, the solution had a density of 8.7 ppg, a TCT of 50° F., and a water activity (a_(w)) of 0.93. This fluid is not highly inhibitive of hydrates, as evidenced by the relatively high a_(w).

[0033] In addition, while specific amounts of chemicals used are described in the above embodiments, it is specifically within the scope of the invention that amounts different from those may be used to provide the desired density.

[0034] For example, in one or more embodiments, a suitable well fluid having a predetermined density may comprise 20% to 50% of methanol and 20% to 50% of monethylene glycol of the total weight percentage. More preferably, in one or more embodiments, a suitable well fluid having a predetermined density may comprise 30% to 45% of methanol and 30% to 45% of monoethylene glycol of the total weight percentage. Still more preferably, in one or more embodiments, a suitable well fluid may comprise 35% to 40% of methanol and 35% to 40% of monoethylene glycol of the total weight percentage.

[0035] Further, in one or more embodiments, a suitable well fluid may comprise a density of 5 ppg to 9 ppg. More preferably, in one or more embodiments, a suitable well fluid may comprise a density of 8.2 ppg to 8.8 ppg. Still more preferably, in one or more embodiments, a suitable well fluid may comprise 8.3 ppg to 8.5 ppg.

[0036] While the foregoing embodiments reference a limited number of compounds, it should be recognized that chemical compounds having the same general characteristics also would function in an analogous fashion. For example, it is expressly within the scope of the present invention that other compounds containing primary, secondary, or tertiary alcohols may be used, such as, for example, diethylene glycol, triethylene glycol, and other glycol derivatives like diethylene glycol methylether, diethylene glycol ethylether, triethylene gylcol methylether, and triethylene glycol ethylether, glycerol and glycerol derivatives like glycerol formal, glycerol 1,3 diglycerolate, glyceroethoxylate, 1,6, hexandiol, and 1,2 cyclohexandiol.

[0037] In general, while the present invention has been described with respect to packer fluids, it is expressly within the scope of the present invention that the fluids disclosed herein may also be used as fluids in or in connection with drilling, drill-in, displacement, completion, hydraulic fracturing, work-over, well-treating, testing, or abandonment.

[0038] While the invention has been described with respect to a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments can be devised which do not depart from the scope of the invention as disclosed herein. Accordingly, the scope of the invention should be limited only by the attached claims. 

What is claimed is:
 1. A well fluid comprising: a glycol compound; and an organic liquid, wherein the glycol compound and the organic liquid are present in amounts selected to achieve a predetermined density suitable for annular pressure control.
 2. The well fluid of claim 1, further comprising water.
 3. The well fluid of claim 1, further comprising a salt solution.
 4. The well fluid of claim 1, wherein the well fluid is substantially water-free.
 5. The well fluid of claim 1, further comprising a polymer, wherein the polymer, the glycol compound, and the organic liquid are present in amounts selected to achieve a predetermined heat capacity.
 6. The well fluid of claim 1, further comprising a polymer, wherein the polymer, the glycol compound, and the organic liquid are present in amounts selected to achieve a predetermined thermal conductivity.
 7. The well fluid of claim 1, further comprising a polymer, wherein the polymer, the glycol compound, and the organic liquid are present in amounts selected to achieve a predetermined viscosity.
 8. The well fluid of claim 3, wherein the salt solution comprises at least one selected from the group consisting of halide brines, formate brines, and acetate brines.
 9. The well fluid of claim 8, wherein the salt solution comprises calcium bromide.
 10. The well fluid of claim 1, wherein the glycol compound comprises at least one selected from the group consisting of ethylene glycol, propylene glycol, and monoethylene glycol.
 11. The well fluid of claim 1, wherein the glycol compound comprises 20% to 50% of a total weight percentage of the well fluid.
 12. The well fluid of claim 11, wherein the glycol compound comprises monoethylene glycol.
 13. The well fluid of claim 1, wherein the organic liquid comprises 20% to 50% of the total weight percentage of the well fluid.
 14. The well fluid of claim 12, wherein the organic liquid comprises methanol.
 15. The well fluid of claim 1, wherein the predetermined density comprises 5 ppg to 9 ppg.
 16. A method of treating a well comprising: injecting a well-treating fluid into the well, wherein the well-treating fluid comprises a glycol compound, and an organic liquid, the glycol compound and the organic liquid present in amounts selected to achieve a predetermined density suitable for annular pressure control.
 17. A well fluid comprising: a glycol compound; and a quaternary amine salt, wherein the glycol compound and the quaternary amine salt are present in amounts selected to achieve a predetermined density suitable for annular pressure control.
 18. The well fluid of claim 17, further comprising an organic liquid.
 19. The well fluid of claim 17, wherein the glycol compound and the quaternary amine salt are selected such that a density of the well fluid decreases when the quaternary amine is added to the glycol compound.
 20. The well fluid of claim 17, wherein the glycol compound comprises at least one selected from the group consisting of ethylene glycol, propylene glycol, and monoethylene glycol. 